Metals, ceramics, glasses, and cermets are used to construct many functional items that are in turn used in carrying out industrial processes. Under certain operating conditions of these processes, surface degradation of a component can result from many causes. These can include the corrosive nature of particular process conditions, thermal effects of the process or environment, contamination from various elements becoming deposited on the surface or infiltrating into the material, deposits formed by catalytic activity between the component's material and the process fluid, galvanic activity between the component's material and the process fluid, concentration cell corrosion, crevice corrosion, graphitic corrosion, and a combination of these degradation mechanisms with each other or with other mechanisms.
During operation, various industrial process systems suffer degradation to the working sections of the system being attacked by various chemicals and conditions. This occurs in the oil industry, colorants industry, cosmetics industry, food industry, pharmaceutical industry, chemical industry, and within closed systems such as cooling systems, heating and air conditioning systems, and many others. Additional systems that are affected by surface degradation are furnaces, boilers, internal combustion engines, gas turbine engine systems, rockets, etc. In any continuous or intermittent process system there is the risk of surface degradation due to the exposure of materials to certain chemicals and conditions. The surfaces exposed to the process may degrade due to the material itself degrading, eroding, or corroding, or the degradation may be in the form of deposits that accumulate on the material, affecting performance of one sort of another, e.g. flow efficiency through a pipe. Any kind of degradation is generally referred to as “fouling.” The typical solution to these types of fouling is to upgrade the material used to construct the functional item, be it a pipe, a heat exchanger, etc. For example, a pipe may be constructed of a nickel alloy stainless steel, rather than of common carbon steel, in an attempt to improve its inner and outer surface longevity and/or functionality. As another example, tanks used to hold various chemical materials may experience material deposits or reactions on the inner surface of the tank, which can adversely affect the overall process efficiency. Coating or lining the interior of the tank with glass may help to reduce these reactions because of the comparatively unreactive nature of the glass. In another example, a heat exchanger may be made from a high nickel content alloy to allow it to withstand high temperature operation (as in the case of a hydrocarbon-fuel gas turbine system) while also reducing the amount of precipitates and deposits that might be occurring due to the caustic environment in which the heat exchanger is required to operate. In yet another example, an exhaust valve for use in an internal combustion engine may be made from a particular alloy in an effort to reduce the amount of carbon deposits forming on its surface; carbon deposits are a well known source of operational and emission problems for internal combustion engines.
Many industrial processes use materials to contain and transport various fluids, slurries, or vapors, and those materials can become degraded during use. These problems are known as “flow assurance” issues, which is the industry term for the growth of flow restrictions in various pipes, tubes, heat exchangers, and process containers, etc. For instance, the interior of a pipeline used in an industrial process may have its effective cross-sectional area reduced during operation by deposits from the chemicals carried within the pipe during various processes. In other cases, the vaporous or liquid elements carried within a heat exchanger may precipitate the growth of crystalline deposits if favorable conditions (temperature, pressure, presence of catalytic elements, etc.) exist within the system. In one example of this problem, crystals of various elements may grow during fluid processing operation because certain exposed molecules within the material surface of the interior of a conduit serve to catalyze the growth of some types of fibers on the interior wall of the conduit. For example, carbon fibers grow on the interior of metal pipes used for ethylene transport, petro-chemical cracking tubes, petroleum refinery heaters, natural gas turbine blades, propane and LPG transport tanks, etc. While the mechanism of carbon fiber formation is not entirely clear, it is believed that exposed iron or other atoms at the surface of a steel or iron pipe in, e.g., a petroleum processing facility, may play a role in decomposing hydrocarbons flowing in the pipe into carbon. Because carbon has some solubility in iron, a steel or iron pipe may absorb this carbon. When the pipe material becomes saturated with carbon, amorphous carbon fibers begin to grow rapidly at process temperatures in the range of about 400° C. to about 800° C. Such deposits and/or fibrous growths affect the boundary layer development of the fluids and/or vapors passing through the pipe's interior, and can cause a significant restriction in the pipe's ability to transfer fluids, vapors, or slurries. Furthermore, a corrosive environment, especially due to the presence of water and impurities or salts dissolved in it, cause corrosion of metal pipes leading to eventual failure. Also, it is known that petrochemical process fluids flowing through a metal tube at high temperature can cause metal wastage in what is known as metal dusting, wherein the tube's inner surface is eroded by various mechanisms. Accordingly, there is a need in the art for a way to prevent or significantly inhibit the growth of carbon fibers while at the same time inhibiting chemical attack of corrosive elements on the substrate, such as those that result in metal dusting of components within a system.
All throughout industry, passageways and chambers regularly experience deposits on their interior surfaces caused by precipitates of the production fluids, deposits exacerbated by high temperatures, solidification of matter in slow moving boundary layers, and deposits occurring by various other mechanisms. Some components, such as heat exchangers, can experience deposits from the processed fluid and from the heat exchange medium, thereby experiencing fouling on multiple interior surfaces. In some cases, more than one interior surface contacts hydrocarbons being processed, such as in a heat exchanger that transfers heat from processed material to feed material. Other components, such as pipelines, can suffer corrosion on outer surfaces due to process and/or environmental factors. The repairing of such problems has large costs associated with it due to interruption of production while sections of a process system are identified and then cleaned, bypassed, and/or replaced. The petroleum industry, for example, has literally thousands of miles of connective pipelines, tubes, manifolds, as well as thousands of heat exchangers and process risers, etc. that require regular maintenance and repair at great costs to the industry. For example, shutting down a petroleum refinery to repair and/or replace flow restricted pipes results in losses of approximately $200,000 to $500,000 per day of lost output.
In another example, at high process pressures and at temperatures above 0° C., methane gas, present in the petrochemical stream may react with water to form ice-like structures called hydrates. Hydrate formation in production-stream flow lines in the petroleum industry is also of great concern. Production-stream flow lines carry the raw, produced fluids from the wellhead to a processing facility. If a flow line is operated in the “hydrate region” (i.e., under conditions at which hydrates can form in an oil or gas wellstream), hydrates can deposit on the pipe's inner wall and agglomerate until they completely block the flow line and stop the transport of hydrocarbons to the processing facility. Attempts to prevent hydrate formation typically involve injecting additives into the process fluid, but this can be a costly solution.
Because the problem of deposits on the interior of process pipes and tubes and the resulting reduction in flow is so large, there are a number of industry associations participating in the study and improvement of flow assurance in fluid processing systems. For example, the Gas Technology Institute estimates that the cost of hydrate formation remediation to industry is over $100 million per year.
Deposits on the interior surface of a pipe have significant negative impact on the pipe's ability to transfer fluids or gases, and these results can vary depending on the surface roughness of the deposit. For example, a smooth deposit of 5% on the interior of a pipe of circular cross-section can cause a loss of throughput of 10%, and require a pressure increase of 30% to maintain constant flow. An uneven deposit of 5% can increase the loss of throughput to 35% and require a pressure increase of 140% to maintain constant flow. See Cordell, Introduction to Pipeline Pigging, 5th Edition (ISBN0-901360-33-3).
Deposit growth on the inside of a pipe can cause deposits or growths to become so large as to nearly stop all fluid flow through the pipe, as shown in FIG. 1. Conditions such as these can occur within a few months, or even within a few weeks of operation in the case of certain industrial processes.
In other applications, scale is caused by precipitates formed within a process system's enclosures during oil and gas recovery, food processing, water treatment, or other industrial processes. The most common scales are inorganic salts such as barium sulphate, strontium sulphate, and calcium carbonate. In some cases the scales may be partly organic (naphthanates, MEG-based etc.). Other scale formations may be composed of sodium chloride, iron carbonate, and magnesium hydroxide. Scales formed from sulphates generally are due to mixing of chemically incompatible waters (like sea water and formation water). Carbonate scales result from pressure release of waters containing bicarbonate at high concentration levels. Scaling degrades the process efficiency by plugging sand screens and production pipe, by causing failures in valves, pumps, heat exchangers, and separators. Scaling may also block transportation pipelines.
Furthermore, combustion buildup known as slag or scale often forms on the flame-heated surfaces of furnaces, boilers, heater tubes, preheaters, and reheaters. The degree of combustion buildup depends on the quality of the fuel being burned. Clean natural gas, for example, produces little or no combustion buildup, while coal, a “dirtier” fuel, produces significant combustion buildup. In particular, coal-fired power plants experience significant combustion buildup on boiler vessels in contact with the coal combustion products. That buildup decreases heat transfer through the surface to the substance being heated, and therefore wastes energy. Also, such combustion buildup increases the applied temperature necessary to cause the substance to achieve a desired temperature. That increased temperature stresses the boiler vessel, and may lead to material failure. Preventing combustion buildup on the flame-heated surfaces of a fluid transport or processing system would reduce energy consumption and extend equipment lifetime.
In some applications, the surfaces exposed to fluid flow may become degraded by the nature of the fluid itself, for example, in the case of hydrogen transport and containment, which has the associated problem of hydrogen embrittlement of the exposed materials.
Throughout industry and technology, sensors detect operational parameters of various processes. By necessity, those sensors inhabit the process material, and are subject to those fouling mechanisms inherent in the processes they monitor. Unfortunately, even the smallest degree of fouling may affect the accuracy of a sensor, even if that same degree of fouling has only a negligible effect on the process itself. Often the remedy to sensor fouling is to design the sensor and sensor mounting apparatus to easily replace fouled sensors. Sensors represent high value components, and frequent sensor replacement adds significant costs in addition to production loss due to shut down for sensor replacement.
The hydrocarbon process industry recognizes several distinct mechanisms for the fouling of process components due to the unique conditions of those processes. One mechanism, known as coking, results from heating hydrocarbons and driving off lighter, lower-boiling fractions causing thermal condensation of heavier fractions. Asphaltenes, tars, inorganic material, and other solids will form on the surfaces of various petrochemical process units. In particular, vacuum columns, fluid catalytic crackers, cokers, viscosity breakers, and any equipment handling heavier oil fractions at high temperatures suffer from the buildup of coke. Also, the high-temperature environment of an ethylene cracker causes polymerization of carbon-carbon double bonds, the product of which condenses and forms coke upon further heating. When high temperature plays a significant role and forms high molecular weight coke, the resulting material is called pyrolytic coke. In a different process, a metal species such as iron or nickel catalyses the dehydrogenation of a hydrocarbon, leading to what is known as catalytic coking. Elemental carbon then deposits in the metal, weakening it. When the system is shut down and cooled for decoking or other maintenance, the weakened metal can crack or spall. In some cases, the carburized metal can spall at process temperatures, resulting in metal dusting mentioned above.
In addition to reducing process throughput, coke buildup decreases heat transfer, requiring higher process temperatures consuming more energy and lowering equipment lifetime. Coke deposits can cause uneven heating, forcing the use of lower temperatures to avoid safety issues. In addition, shutting down those systems to decoke stops production. System shut downs and restarts cause thermal stress and increase the likelihood of system malfunctions and material failure. Reducing coke buildup can extend equipment lifetime, improve process throughput, lower energy consumption and operating temperatures, increase safety, and makes less-expensive alloys available for equipment construction. Moreover, increasing the actual temperature of the process stream (not just the temperature of the outside of the heated vessels) would increase process efficiency and throughput. As it is, many process temperatures are limited by the metallurgy of the heater tubes. Coke buildup requires higher temperatures to be applied outside to obtain a given temperature inside those tubes.
A second distinct mechanism for fouling equipment in the hydrocarbon industry is corrosion by one or more chemicals present in the process stream. In particular, hydrogen sulfide (H2S) attacks metal surfaces, causing the formation of iron sulfates that flake from hydrocarbon-contacting surfaces, reducing the thickness and strength of process equipment, clogging passages, and potentially diminishing the activity of catalysts downstream. The presence of ammonia (NH3), ammonium chloride (NH4Cl), or hydrogen (H and H2) enhances corrosive attack by H2S. Furthermore, acids such as hydrochloric acid (HCl), naphthenic acid, sulfuric acid (H2SO4), and hydrofluoric acid (HF) cause corrosive attack at various points in hydrocarbon processing systems. For example, naphthenic acid corrosion can be observed in process equipment handling diesel and heavier fractions, because naphthenic acids tend to have boiling points similar to diesel fractions. Corrosion by sulfuric acid and hydrofluoric acids occurs in alkylating units and associated components employing those acids. Protection against corrosive mechanisms may be found in using chromium, nickel, and molybdenum alloys, and by adding substances to the process stream such as base to neutralize acid. Ironically, H2S is added to process streams to reduce metal dusting and other forms of fouling; yet H2S itself causes corrosion. That compound also arises during hydrodesulfuring processes, when thiols and other naturally-present organosulfur compounds react to form H2S and desulfured hydrocarbons. In addition, metal systems handling alternative fuels such as alcohols including methanol and ethanol have been shown to experience corrosion. Protecting equipment against those corrosive mechanisms can lower operating costs, increase run length, extend equipment life, and make less-expensive materials available for equipment construction.
As petroleum resources become less plentiful and more expensive, renewable sources of hydrocarbons increase in importance. Biodiesel, for example, promises an alternative fuel to petrodiesel, the fuel derived from crude oil. However, biodiesel refining presents unique challenges to refining equipment. Typically, a strong base such as sodium hydroxide or potassium hydroxide in alcohol digests triglycerides and long-chain fatty acids from a biological or renewable source, to form esterified fatty acids (biodiesel) and glycerin. That source may be corn, soy, oil palm, pulp, bark, even restaurant waste and garbage. The harsh basic environment required for the digestion reaction may cause caustic stress corrosion cracking, also known as caustic embrittlement. Heat treatments and nickel-based alloys may be necessary to avoid cracking, unless a less-expensive or more-effective means can be found to protect that equipment.
Surfaces that become contaminated with debris during process operation often adversely affect the efficiency and/or functionality of the process itself. Currently, most cleaning methods to remove deposits on interior surfaces within systems of the types described above in process plants involve using one or more of the following strategies:                Chemical solvents such as kerosene or diesel fuel, or stronger aromatic solvents such as xylene or toluene.        Dispersants that act as surfactants        Exothermic chemical reactions        Mechanical cleaning methods such as pigging or jetting        Thermal cleaning methods that involve hot oil or diesel fuel, or the external application of high heat to break down surface deposits        
These methods involve considerable time and effort on the part of process plant maintenance personnel, reducing output or throughput of a system and causing the associated loss of revenue to the plant.
Similarly, in powder metal spraying operations, chemical attack occurs within the spraying chamber that rapidly degrades its interior surfaces. In other applications such as food processing, beverage production, and similar closed process systems, material degradation on the interior surface of many portions of a process system occurs due to chemical attack, material deposits, fibrous growth, and other surface contaminants.
Portions of fluid processing and transport systems exposed to the environment, especially those containing iron, also experience corrosion from environmental factors. Chemical, thermal, and galvanic attack represent leading mechanisms of exterior surface fouling in those systems.
There exists, therefore, the need for an improved means of protecting the surfaces in many functional components from a variety of contaminants that build up or chemical erosion that occurs, through various mechanisms, during the component's normal operation. An improved surface treatment that can be affordably applied and that provides a demonstrable resistance to surface contamination would serve to improve many processes currently in use throughout industry. The invention disclosed herein addresses this need.